Most hydrocarbon wells are drilled in successively lower casing sections, with a selected size casing run in a drilled section prior to drilling the next lower smaller diameter section of the well, then running in a reduced diameter casing size in the lower section of the well. The depth of each drilled section is thus a function of (1) the operator's desire to continue drilling as deep as possible prior to stopping the drilling operation and inserting the casing in the drilled section, (2) the risk that upper formations will be damaged by high pressure fluid required to obtain the desired well balance and downhole fluid pressure at greater depths, and (3) the risk that a portion of the drilled well may collapse or otherwise prevent the casing from being run in the well, or that the casing will become stuck in the well or otherwise practically be prevented from being run to the desired depth in a well. A significant cost of drilling and completing of the well involves the use of increased diameter sections moving upward from the total depth (TD) to the surface. From the standpoint of fluid flow, a 7⅝ inch casing near the total depth may be sufficient to transmit the desired fluids to the surface through a production tubing string, but the size of the outside casing increases from 7⅝ inches to, e.g., 17½ inches, in order that each upper section of casing be able to accommodate the small diameter sections which are run in the well.
To avoid the above problems, various techniques have been proposed for expanding a casing string downhole, in some applications so that the expanded diameter casing string has an internal diameter approximately equal to the internal diameter of the “full bore” casing string through which the smaller diameter tubular passed before being expanded while downhole. Thus in some proposed applications, substantially the entirety of a casing string from TD to surface may be substantially the same “full bore” diameter, so that, for example, if a 7⅝ inch casing ID is installed at the surface, a smaller diameter casing may be passed through the 7⅝ inch casing, which typically may be cemented in the well, and the smaller diameter casing then expanded downhole to 7⅝ inch ID casing. Successively lower sections of the well similarly may be completed by passing the smaller diameter casing downhole of a cemented 7⅝ inch casing section, then expanding the tubular while downhole to continue the 7⅝ inch casing run. In other applications, only a portion of the tubular need be expanded downhole to this “full bore” diameter to obtain the benefits for this technology. U.S. Pat. Nos. 5,348,095, 5,366,012 and 5,667,011 to Shell Oil Company disclose casing expansion techniques, as do early U.S. Pat. Nos. 3,179,168, 3,245,471 and 3,358,760. U.S. Pat. Nos. 6,021,850, 6,050,341, 5,390,742, 5,785,120 and 6,250,385, as well as publication U.S. 2001/002053241, disclose various types of equipment for expanding a downhole tubular in a well. SPE Papers 56500, 62958, 77612 and 77940, and Offshore January 2003, pp. 62, 64, discuss the commercial advantages of downhole casing expansions in terms of lower well completion costs.
Problems have nevertheless limited the acceptance of casing systems expanded downhole, including difficulties associated with the reliability and cost of expanding the tubular downhole. In most applications, the drilling operator must run a caliper through the drilled borehole to determine the borehole geometry and thereby determine if the borehole has, for example, too great of a spiral to initially run the tubular in the borehole prior to the expansion operation.
The disadvantages of the prior art are overcome by the present invention, and an improved expanded casing (or other tubular) system and method are hereinafter disclosed which will result in lower costs for drilling and completing a well, and improved well quality for enhanced hydrocarbon recovery.